Wells for production of hydrocarbon fluids such as oil and natural gas are typically drilled by connecting a drill bit to the lower end of a drill string made up of sections (or “joints”) of drill pipe connected end-to-end by means of threaded connections, and then rotating the drill bit into the ground until the bit penetrates a hydrocarbon-producing subsurface formation. After the well has been drilled, it is typically necessary to line the wellbore with tubular casing to prevent soil materials from sloughing into the wellbore and thus partially or completely collapsing the wellbore. Accordingly, after the drill string as been withdrawn from the drilled wellbore, a casing string is installed in the wellbore. The casing string is made up of pipe sections having a diameter larger than the drill pipe, and slightly smaller than the wellbore, and the resultant annular space between the casing and the wellbore is filled with a cement slurry. The process of installing casing in a drilled wellbore is commonly referred to as “casing running”.
Although it has in the past been most common for wells to be drilled using the drilling and casing procedures described above, it has become increasingly common for wells to be drilled using casing as the drill string, with the drill bit connected to the lower end of the casing string (a procedure commonly referred to as “casing drilling” or “drilling with casing”). When the wellbore reaches the target formation, the casing string is simply cemented into place. This procedure necessitates leaving the drill bit underground, but the cost of the drill bit is outweighed by savings in both time and money by not needing to use a separate drill string and withdraw it from the wellbore, and then running casing into the wellbore in a separate operation.
When drilling a wellbore using a top-drive-equipped drilling rig, it is well known to include a device known as a “floating cushion sub” at the upper end of the drill string, i.e., near the top drive quill. (The term “sub” is commonly used in the oil and gas industry with reference to any small or secondary drill string component.) Floating cushions subs are capable of transmitting torque through a limited axial stroke range (which is why they are referred to as “floating”). At one or both ends of the axial stroke range, a floating cushion sub provides axial load transfer (compression or hoist load) through a compliant element (typically an elastomeric element) that acts as a “cushion”. Together with frictional drag, this cushion tends to damp the transmission of drilling vibrations initiated at the drill bit that would otherwise be transmitted upward into the top drive and rig structure, which is not a desirable condition.
Examples of known floating cushion subs may be seen in U.S. Pat. No. 4,055,338 (Dyer); U.S. Pat. No. 4,192,155 (Gray); U.S. Pat. No. 4,759,738 (Johnson); U.S. Pat. No. 4,844,181 (Bassinger); U.S. Pat. No. 5,224,898 (Johnson et al.); and U.S. Pat. No. 6,332,841 (Secord).
One of the routine procedures carried out during well drilling operations is the connection of a new segment (or “joint”) of drill pipe to the drill string, by threading the new pipe joint into the upper end of the drill string. This connection procedure is commonly referred to as “making up” a connection, while the reverse procedure is referred to as “breaking out” the connection. Typically, the upper end of each joint of pipe in the drill string carries a female thread and is referred to as a “box end”, while the lower end of each joint carries a male thread and is referred to as a “pin end”.
When drilling using a top-drive-equipped drilling rig, connection make-up requires a reduction in the vertical distance between the top drive and the already-assembled drill string (which is suspended from the rig floor), as the new pipe joint (suspended from the top drive) is being threaded into the drill string. If the vertical position of the top drive is not adjusted during make-up, this axial movement tends to induce axial tensile loading in the drill string as a function of the prevailing system stiffness. This axial tension must be resisted at the thread interface during relative rotation of the pin end and box end threads of the connection being made up. This axial tension across the thread interface tends to increase thread wear and can lead to thread damage such as galling.
Breaking out a threaded connection has the reverse effect; i.e., there needs to be an increase in the vertical distance between the top drive and the upper end of the drill string from which a pipe joint is being removed, to prevent the development of compression across the thread interface.
By providing a range of free axial stroke (or float), a floating cushion sub can be interposed between the top drive and the pipe joint being added or removed, to effectively provide the vertical reduction or increase required for connection make-up or break-out, thereby making it unnecessary to adjust the vertical position of the top drive. However, this still typically results in the weight of at least one joint of pipe being carried by threads.
Top drive rigs are now being used not only to assemble drill strings, but also to assemble casing strings and production tubing strings, and the pipe most commonly used for casing and production tubing have less robust threads than typical drill pipe. Accordingly, there is an increased need for means to better manage the axial loads induced during make-up and break-out operations using top drives, particularly in the context of casing and tubing strings. Simply pressing a known type of floating cushion sub into new service is not always possible or optimally effective, due to limitations in hoisting capacity of the sub, due to the axial load needing to be further reduced to avoid thread damage, and/or due to the need or desire to expedite make-up and break-out by not requiring the vertical position of the top drive to be adjusted as frequently or with as much precision as might otherwise be required. Furthermore, axial float may provide similar advantages for use with casing running tools the length of which changes during normal operation; see, for example, the “Gripping Tool” disclosed in U.S. Pat. No. 7,909,120.